SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                   FORM 10-KSB
(Mark One)

(X)   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
                                    EXCHANGE ACT OF 1934

For the Fiscal Year Ended January 31, 2003
                                             OR
( )   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
                                    EXCHANGE ACT OF 1934

Commission File No. 0-33259

                             ENERGAS RESOURCES, INC.
                 (Name of Small Business Issuer in its charter)

                Delaware                                    73-1620724
         (State of incorporation)                        (IRS Employer
                                                       Identification No.)

      800 Northeast 63rd Street
       Oklahoma City, Oklahoma                                   73105
   (Address of Principal Executive Office)                     Zip Code

Registrant's telephone number, including Area Code: (405)-879-1752
Securities registered pursuant to Section 12(b) of the Act:  None
Securities registered pursuant to Section 12(g) of the Act:

                                        Common Stock
                                      (Title of Class)

Check whether the Registrant  (1) has filed all reports  required to be filed by
Section 13 or 15(d) of the  Securities  Exchange  Act of 1934 during the past 12
months (or for such shorter period that the Registrant was required to file such
reports)  and (2) has been subject to such filing  requirements  for the past 90
days.

                                            X          __
                                           YES         NO

Check if disclosure  of delinquent  filers in response to Item 405 of Regulation
S-B is not contained in this form, and no disclosure  will be contained,  to the
best  of  the  Registrant's   knowledge,  in  definitive  proxy  or  information
statements  incorporated  by  reference  in Part III of this Form  10-KSB or any
amendment to this Form 10-KSB. [X]

The Company's revenues during the year ended January 31, 2003 were $142,743.

The  aggregate  market value of the voting stock held by  non-affiliates  of the
Company,  (16,112,315  shares)  based upon the  closing  price of the  Company's
common stock on May 14, 2003 was approximately $4,028,000.

Documents incorporated by reference:      None

As of May 14, 2003 the Company had 26,143,001  issued and outstanding  shares of
common stock.

<PAGE>


                 CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING NFORMATION

     This report includes  "forward-looking  statements".  All statements  other
than  statements of historical  facts included in this  Registration  Statement,
regarding the Company's financial  position,  reserve quantities and net present
values, business strategy, plans and objectives of management of the Company for
future  operations and capital  expenditures,  are  forward-looking  statements.
Although  the  Company   believes  that  the   expectations   reflected  in  the
forward-looking  statements and the assumptions upon which such  forward-looking
statements  are  based  are  reasonable,  it can  give no  assurance  that  such
expectations and assumptions will prove to have been correct.  Reserve estimates
are  generally  different  from the  quantities  of oil and natural gas that are
ultimately recovered.


<PAGE>


                                          GLOSSARY

         The following terms are used throughout this report:

     BBL. One stock tank barrel, or 42 U.S. gallons liquid volume,  usually used
herein in reference to crude oil or other liquid hydrocarbons.

     BOE.  Equivalent  barrels of oil, using the ratio of six Mcf of natural gas
to one Bbl of crude oil, condensate or natural gas liquids.

     BTU. A British  thermal unit which is the amount of heat  required to raise
the temperature of one avoirdupois pound of pure water form 58.5 degrees to 59.5
degrees Fahrenheit under standard conditions.

     DEVELOPED ACREAGE. The number of acres which are allocated or assignable to
producing wells or wells capable of production.

     DEVELOPMENT  WELL.  A well  drilled  as an  additional  well  to  the  same
reservoir as other producing wells on a Lease, or drilled on an offset Lease not
more than one location away from a well producing from the same reservoir.

     EXPLORATORY  WELL. A well drilled in search of a new  undiscovered  pool of
oil or gas, or to extend the known limits of a field under development.

     GROSS ACRES OR WELLS. A well or acre in which a working  interest is owned.
The  number  of gross  wells is the  total  number  of wells in which a  working
interest is owned.

     LEASE. Full or partial  interests in an oil and gas lease,  authorizing the
owner thereof to drill for,  reduce to  possession  and produce oil and gas upon
payment of rentals,  bonuses and/or royalties.  Oil and gas leases are generally
acquired from private landowners and federal and state governments.  The term of
an oil and gas lease  typically  ranges  from  three to ten  years and  requires
annual lease rental  payments of $1.00 to $2.00 per acre.  If a producing oil or
gas well is drilled on the lease prior to the expiration of the lease, the lease
will generally  remain in effect until the oil or gas  production  from the well
ends. The Company is required to pay the owner of the leased  property a royalty
which is usually  between 12.5% and 16.6% of the gross amount  received from the
sale of the oil or gas produced from the well.

         MCF. One thousand cubic feet.

     NET ACRES OR WELLS.  A net well or acre is deemed to exist  when the sum of
fractional  ownership  working interests in gross wells or acres equals one. The
number  of net  wells or acres is the sum of the  fractional  working  interests
owned in gross wells or acres expressed as whole numbers and fractions.

<PAGE>

     OPERATING  COSTS.  The expenses of  producing  oil or gas from a formation,
consisting  of the costs  incurred  to operate  and  maintain  wells and related
equipment  and  facilities,  including  labor  costs,  repair  and  maintenance,
supplies, insurance, production, severance and other production excise taxes.

     PRODUCING  PROPERTY.  A property (or interest therein) producing oil or gas
in commercial  quantities or that is shut-in but capable of producing oil or gas
in  commercial  quantities,  to which  Producing  Reserves  have been  assigned.
Interests  in a property may include  Working  Interests,  production  payments,
Royalty Interests and other non-working interests.

     PRODUCING RESERVES.  Proved Developed Reserves expected to be produced from
existing completion intervals open for production in existing wells.

     PROSPECT.  An area in which a party owns or intends to acquire  one or more
oil  and  gas  interests,  which  is  geographically  defined  on the  basis  of
geological  data and which is  reasonably  anticipated  to  contain at least one
reservoir of oil, gas or other hydrocarbons.

     PROVED  DEVELOPED  RESERVES.  Proved  developed  oil and gas  reserves  are
reserves  that can be  expected  to be  recovered  through  existing  wells with
existing equipment and operating methods.  Additional oil and gas expected to be
obtained  through the application of fluid injection or other improved  recovery
techniques  for  supplementing  the  natural  forces and  mechanisms  of primary
recovery may be included as "proved developed  reserves" only after testing by a
pilot  project or after the  operation  of an  installed  program has  confirmed
through production response that increased recovery will be achieved.

     PROVED RESERVES.  Proved oil and gas reserves are the estimated  quantities
of crude oil,  natural  gas,  and  natural  gas  liquids  which  geological  and
engineering  data  demonstrate  with  reasonable  certainty to be recoverable in
future  years  from known  reservoirs  under  existing  economic  and  operating
conditions,  i.e.,  prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.

     (i) Reservoirs are considered proved if economic producibility is supported
by either  actual  production  or conclusive  formation  testing.  The area of a
reservoir considered proved includes (a) that portion delineated by drilling and
defined by gas-oil and/or  oil-water  contacts,  if any; and (b) the immediately
adjoining  portions  not yet  drilled,  but  which can be  reasonably  judged as
economically  productive on the basis of available  geological  and  engineering
data.  In the  absence  of  information  on fluid  contacts,  the  lowest  known
structural  occurrence  of  hydrocarbons  controls the lower proved limit of the
reservoir.

     (ii) Reserves  which can be produced  economically  through  application of
improved  recovery  techniques  (such as fluid  injection)  are  included in the
"proved"  classification  when  successful  testing by a pilot  project,  or the
operation of an installed  program in the  reservoir,  provides  support for the
engineering analysis on which the project or program was based.

<PAGE>


     (iii)  Estimates of proved  reserves do not include the following:  (a) oil
that may become available from known reservoirs but is classified  separately as
"indicated  additional  reserves",  (b) crude oil,  natural gas, and natural gas
liquids,  the  recovery  of which is  subject  to  reasonable  doubt  because of
uncertainty as to geology, reservoir  characteristics,  or economic factors; (c)
crude oil,  natural gas,  and natural gas  liquids,  that may occur in undrilled
prospects;  and (d) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.

     PROVED  UNDEVELOPED  RESERVES.  Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled  acreage,
or from  existing  wells where a relatively  major  expenditure  is required for
recompletion.  Reserves on undrilled acreage are limited to those drilling units
offsetting  productive  units that are  reasonably  certain of  production  when
drilled.  Proved reserves for other undrilled units can be claimed only where it
can be  demonstrated  with certainty that there is continuity of production from
the  existing  productive   formation.   Proved  undeveloped  reserves  are  not
attributable to any acreage for which an application of fluid injection or other
improved  recovery  technique is contemplated,  unless such techniques have been
proved effective by actual tests in the area and in the same reservoir.

     ROYALTY  INTEREST.  An interest in an oil and gas  property  entitling  the
owner to a share of oil and gas production free of Operating Costs.

     UNDEVELOPED  ACREAGE.  Lease acres on which wells have not been  drilled or
completed to a point that would permit the  production of commercial  quantities
of oil and gas  regardless  of  whether  or not  such  acreage  contains  proved
reserves.  Undeveloped  acreage  should not be confused with  undrilled  acreage
which is "Held by Production" under the terms of a lease.

     WORKING  INTEREST.  The  operating  interest  under a Lease which gives the
owner  the right to drill,  produce  and  conduct  operating  activities  on the
property and a share of production,  subject to all Royalty  Interests and other
burdens and to all costs of  exploration,  development  and  operations  and all
risks in connection therewith.

<PAGE>

ITEM 1.  DESCRIPTION  OF  BUSINESS

     Energas  Resources,  Inc.  was  incorporated  under  the  laws  of  British
Columbia,  Canada on November 2, 1989 and on August 20, 2001 the Company  became
domesticated and incorporated in Delaware.

     The Company is involved in the  exploration and development of oil and gas.
The  Company's  activities  are primarily  dependent  upon  available  financial
resources  to fund the costs of  drilling  and  completing  wells.  The  Company
conducts  its oil and gas  exploration  and  production  activities  through its
wholly-owned subsidiary, A.T. Gas Gathering Systems, Inc.

     The  Company  also owns and  operates a natural gas  gathering  system that
serves the wells operated by the Company for delivery to a mainline transmission
system.  This system is located in Atoka  County,  Oklahoma and consists of four
miles of pipeline and is connected to four wells that supply natural gas.

     As of May 14, 2003 the Company  owned  interests  in six Gross  (2.395 Net)
Wells, all of which were operated by the Company.

     With the exception of the Company's  natural gas gathering  system,  all of
the Company's oil and gas properties are leased.

     The Company's  corporate  offices are located at 800 Northeast 63rd Street,
Third Floor,  Oklahoma City,  Oklahoma  73105 and its telephone  number is (405)
879-1752.

PRINCIPAL AREAS OF OPERATION

     The Company  principally  operates in the Arkoma  Basin in Oklahoma and the
Powder River Basin in Wyoming.

     As of May 14, 2003 the Company had four gas wells in the Arkoma Basin which
were  producing  approximately  255  Mcf of  gas  per  day.  At  May  14,  2003,
approximately  95% of the Company's Proved Developed  Reserves were attributable
to the Arkoma Basin.

     The  Company's  oil  and gas  production  in the  Powder  River  Basin  are
attributable to two wells in Rusty Creek Prospect in Niobrara  County,  Wyoming.
The Company does not intend to drill any additional  wells on this prospect.  As
of May 14, 2003 the Company's two wells in the Rusty Creek Prospect were shut in
due to workover  operations,  but were  capable of producing  approximately  ten
barrels of crude oil per day. At May 14, 2003, approximately 5% of the Company's
Proved Developed Reserves were attributable to the Powder River Basin.

         PROSPECT ORIGINATION

     The Company evaluates undeveloped oil and gas prospects and participates in
drilling  activities on those  prospects  which in the opinion of management are
favorable  for  the  production  of  oil or  gas.  If,  through  its  review,  a
geographical  area  indicates  geological  and economic  potential,  the Company

<PAGE>

attempts  to  acquire  Leases  or other  interests  in the area and  assemble  a
Prospect.  The Company  normally sells portions of its leasehold  interests in a
Prospect to  unrelated  third  parties,  thus  sharing  risks and rewards of the
exploration and development of the Prospect with the joint owners pursuant to an
operating agreement. One or more Exploratory Wells may be drilled on a Prospect,
and if the results  indicate the presence of  sufficient  oil and gas  reserves,
additional  Development  Wells  may be  drilled  on the  Prospect.  The  Company
typically  seeks  potential  joint  venture  partners  for  development  of  its
Prospects.

NATURAL GAS GATHERING SYSTEM

     The Company owns a pipeline gathering system that serves the wells operated
by the Company in Atoka  County,  Oklahoma.  The  gathering  system has a design
capacity of  8,000,000  cubic feet per day.  The  pipeline  system was placed in
service and received  the first  delivery of natural gas in November  1988.  The
gathering  system is operated by an affiliate of the Company,  Energas  Pipeline
Company that is owned by George G. Shaw, an executive  officer and a Director of
the Company. The natural gas is gathered under a five-year contract (with annual
one-year  renewals)  and is currently  purchased by Duke Energy Field  Services,
Inc. The Company, as opposed to Energas Pipeline Company, is responsible for all
costs of operating the gathering system.  Energas Pipeline Company purchases the
produced  natural gas at the wellhead at a price that is $.49/mcf  less than the
price paid by Duke Energy Field Services,  Inc.  Energas  Pipeline then pays the
Company $.17/mcf as a fee for the use of its gathering system.

      During the years ended January 31, 2003 and 2002:

     o    Energas Pipeline  Company received $14,428 and $13,765,  respectively,
          for its gathering services,

     o    the Company  received  revenues  of $15,808 and $15,542  respectively,
          from its gathering system, and

     o    the  Company  incurred  direct  pipeline  costs of $20,793  and $3,292
          respectively.

     During the years indicated,  natural gas deliveries throughout the pipeline
system were :

      Year Ended                    Gas Delivered (Mcf)

      January 31, 2001                    90,377
      January 31, 2002                    94,433
      January 31, 2003                    92,986

     The pipeline gathering system consists approximately of five miles of pipe.
The pipeline  system  receives  natural gas from the Company's four gas wells in
the Arkoma Basin.

     The Company does not gather or transport natural gas other than by means of
its gathering system.

<PAGE>

GOVERNMENT REGULATION

     Various state and federal agencies  regulate the production and sale of oil
and natural gas. All states in which the Company operated impose restrictions on
the drilling, production, transportation and sale of oil and natural gas.

     Under the Natural Gas Act of 1938, the Federal Energy Regulatory Commission
(the "FERC") regulates the interstate  transportation and the sale in interstate
commerce  for resale of natural  gas. The FERC's  jurisdiction  over  interstate
natural gas sales has been substantially  modified by the Natural Gas Policy Act
under which the FERC continued to regulate the maximum selling prices of certain
categories of gas sold in "first sales" in interstate and intrastate commerce.

     Effective January 1, 1993, however,  the Natural Gas Wellhead Decontrol Act
(the "Decontrol  Act")  deregulated  natural gas prices for all "first sales" of
natural gas.  Because "first sales" include typical wellhead sales by producers,
all natural gas produced  from the Company's  natural gas  properties is sold at
market  prices,  subject to the terms of any private  contracts  which may be in
effect. The FERC's  jurisdiction over natural gas transportation is not affected
by the Decontrol Act.

     The  Company's  sales of natural  gas will be affected  by  intrastate  and
interstate gas  transportation  regulation.  Beginning in 1985, the FERC adopted
regulatory  changes  that have  significantly  altered  the  transportation  and
marketing  of natural  gas.  These  changes  are  intended by the FERC to foster
competition by, among other things, transforming the role of interstate pipeline
companies  from  wholesale  marketers  of natural gas to the primary role of gas
transporters.  All natural gas  marketing by the pipelines is required to divest
to a marketing affiliate,  which operates separately from the transporter and in
direct competition with all other merchants.  As a result of the various omnibus
rulemaking   proceedings  in  the  late  1980s  and  the   individual   pipeline
restructuring  proceedings of the early to mid-1990s,  the interstate  pipelines
must    provide     open    and     nondiscriminatory     transportation     and
transportation-related   services  to  all  producers,   natural  gas  marketing
companies,  local  distribution  companies,   industrial  end  users  and  other
customers seeking service. Through similar orders affecting intrastate pipelines
that provide similar interstate  services,  the FERC expanded the impact of open
access regulations to intrastate commerce.

     More  recently,  the FERC has pursued  other policy  initiatives  that have
affected natural gas marketing. Most notable are (1) the large-scale divestiture
of  interstate   pipeline-owned  gas  gathering   facilities  to  affiliated  or
non-affiliated  companies;  (2)  further  development  of  rules  governing  the
relationship  of  the  pipelines  with  their  marketing  affiliates;   (3)  the
publication of standards  relating to the use of electronic  bulletin boards and
electronic  data  exchange by the  pipelines  to make  available  transportation
information  on a timely basis and to enable  transactions  to occur on a purely
electronic  basis;  (4) further  review of the role of the secondary  market for
released  pipeline  capacity and its  relationship to open access service in the
primary  market;  and (5)  development  of  policy  and  promulgation  of orders
pertaining to its  authorization of market-based  rates (rather than traditional
cost-of-service  based  rates)  for  transportation  or   transportation-related
services  upon the  pipeline's  demonstration  of lack of market  control in the

<PAGE>

relevant service market.  The Company does not know what effect the FERC's other
activities will have on the access to markets,  the fostering of competition and
the cost of doing business.

     As a result of these changes, sellers and buyers of natural gas have gained
direct access to the particular  pipeline services they need and are better able
to  conduct  business  with a larger  number of  counter  parties.  The  Company
believes these changes generally have improved the access to markets for natural
gas while, at the same time, substantially increasing competition in the natural
gas  marketplace.  The Company cannot predict what new or different  regulations
the FERC and  other  regulatory  agencies  may adopt or what  effect  subsequent
regulations  may  have on  production  and  marketing  of  natural  gas from the
Company's properties.

     In the past,  Congress  has been very  active  in the area of  natural  gas
regulation. However, as discussed above, the more recent trend has been in favor
of  deregulation  and the promotion of  competition in the natural gas industry.
Thus,  in  addition  to  "first  sales"  deregulation,  Congress  also  repealed
incremental  pricing  requirements  and  natural gas use  restraints  previously
applicable.  There are other  legislative  proposals  pending in the Federal and
State legislatures which, if enacted,  would significantly  affect the petroleum
industry.  At the present time, it is impossible to predict what  proposals,  if
any, might actually be enacted by Congress or the various state legislatures and
what effect,  if any, these proposals might have on the production and marketing
of natural gas by the Company.  Similarly,  and despite the trend toward federal
deregulation  of the natural gas industry,  whether or to what extent that trend
will  continue  or  what  the  ultimate  effect  will be on the  production  and
marketing of natural gas by the Company cannot be predicted.

     The  Company's  sales of oil and natural gas liquids are not  regulated and
are at market prices. The price received from the sale of these products will be
affected  by the cost of  transporting  the  products  to  market.  Much of that
transportation is through interstate common carrier  pipelines.  Effective as of
January 1, 1995, the FERC implemented  regulations generally  grandfathering all
previously approved interstate transportation rates and establishing an indexing
system for those rates by which  adjustments are made annually based on the rate
of inflation,  subject to certain conditions and limitations.  These regulations
may tend to  increase  the cost of  transporting  oil and natural gas liquids by
interstate  pipeline,  although the annual  adjustments  may result in decreased
rates in a given  year.  These  regulations  have  generally  been  approved  on
judicial  review.  Every five  years,  the FERC will  examine  the  relationship
between the annual  change in the  applicable  index and the actual cost changes
experienced  by the oil  pipeline  industry.  The Company is not able to predict
with certainty what effect, if any, these relatively new federal  regulations or
the periodic review of the index by the FERC will have on the Company.

     Federal,  state,  and local agencies have  promulgated  extensive rules and
regulations  applicable  to the  Company's  oil  and  natural  gas  exploration,
production  and related  operations.  Most states  require  permits for drilling
operations,  drilling bonds and the filing of reports concerning  operations and
impose other  requirements  relating to the  exploration of oil and natural gas.
Many states also have statutes or regulations  addressing  conservation  matters
including  provisions  for the  unitization  or pooling of oil and  natural  gas
properties,  the  establishment  of  maximum  rates of  production  from oil and
natural gas wells and the  regulation of spacing,  plugging and  abandonment  of
such wells.  The statutes and regulations of some states limit the rate at which

<PAGE>

oil and natural gas is produced from the Company's  properties.  The federal and
state  regulatory  burden on the oil and  natural  gas  industry  increases  the
Company's  cost of doing business and affects its  profitability.  Because these
rules and regulations are amended or  reinterpreted  frequently,  the Company is
unable to predict the future cost or impact of complying with those laws.

COMPETITION AND MARKETING

     The Company is faced with strong  competition from many other companies and
individuals  engaged  in the oil and gas  business,  many are very  large,  well
established  energy  companies with  substantial  capabilities  and  established
earnings records. The Company may be at a competitive  disadvantage in acquiring
oil and  gas  prospects  since  it  must  compete  with  these  individuals  and
companies,  many of which have greater financial  resources and larger technical
staffs. It is nearly impossible to estimate the number of competitors;  however,
it is known that there are a large number of companies  and  individuals  in the
oil and gas business.

     Exploration  for  and  production  of  oil  and  gas  are  affected  by the
availability of pipe, casing and other tubular goods and certain other oil field
equipment   including   drilling  rigs  and  tools.  The  Company  depends  upon
independent  drilling  contractors to furnish rigs, equipment and tools to drill
its  wells.  Higher  prices  for oil and gas may  result  in  competition  among
operators for drilling  equipment,  tubular  goods and drilling  crews which may
affect the Company's ability  expeditiously to drill,  complete,  recomplete and
work-over  its wells.  However,  the  Company has not  experienced  and does not
anticipate difficulty in obtaining supplies, materials, drilling rigs, equipment
or tools.

     The Company does not refine or otherwise  process crude oil and  condensate
production.  Substantially all of the crude oil and condensate production of the
Company's wells are sold at posted prices under short-term  contracts,  which is
customary in the industry.

     The  Company's  gas  production  is  currently  sold to Duke  Energy  Field
Services, Inc.

     The market for oil and gas is dependent upon a number of factors beyond the
Company's control, which at times cannot be accurately predicted.  These factors
include the proximity of wells to, and the capacity of,  natural gas  pipelines,
the extent of  competitive  domestic  production and imports of oil and gas, the
availability  of other sources of energy,  fluctuations  in seasonal  supply and
demand,  and  governmental   regulation.   In  addition,  there  is  always  the
possibility  that new  legislation  may be  enacted  which  would  impose  price
controls  or  additional  excise  taxes upon crude oil or natural  gas, or both.
Oversupplies  of natural  gas can be expected to recur from time to time and may
result in the gas producing  wells being shut-in.  Increased  imports of natural
gas,  primarily  from Canada,  have occurred and are expected to continue.  Such
imports may adversely affect the market for domestic natural gas.

     Since  the  early   1970's  the  market   price  for  crude  oil  has  been
significantly affected by policies adopted by the member nations of Organization
of Petroleum Exporting Countries ("OPEC").  Members of OPEC establish prices and
production quotas among themselves for petroleum products from time to time with
the intent of  controlling  the current  global  supply and  consequently  price

<PAGE>

levels.  The Company is unable to predict the effect, if any, that OPEC or other
countries will have on the amount of, or the prices  received for, crude oil and
natural gas produced and sold from the Company's wells.

     Gas  prices,   which  were  once   effectively   determined  by  government
regulations,  are now largely  influenced by  competition.  Competitors  in this
market  include  producers,   gas  pipelines  and  their  affiliated   marketing
companies,  independent  marketers,  and providers of alternate energy supplies,
such as residual  fuel oil.  Changes in government  regulations  relating to the
production,  transportation  and  marketing of natural gas have also resulted in
significant  changes  in the  historical  marketing  patterns  of the  industry.
Generally,  these changes have resulted in the  abandonment by many pipelines of
long-term  contracts  for the purchase of natural gas,  the  development  by gas
producers of their own marketing  programs to take advantage of new  regulations
requiring  pipelines to transport  gas for  regulated  fees,  and an  increasing
tendency to rely on short-term contracts priced at spot market prices.

DRILLING ACTIVITIES

     During the periods  indicated,  the Company  drilled or participated in the
drilling of the following wells:

                                             Year Ended January 31,
                                 2001                 2002             2003
                           Gross     Net      Gross     Net     Gross    Net
Exploratory Wells (1):
  Productive:
   Oil                      --       --         --      --         --     --
   Gas                      --       --         --      --         --     --
  Nonproductive             --       --         --      --         --     --

Development Wells (1):
  Productive:
   Oil                      --       --         --      --         --     --
   Gas                      --       --         --      --         --     --
  Nonproductive              1      0.5         --      --         --     --

Total Wells (1):
  Productive:
   Oil                      --       --         --      --         --     --
   Gas                      --       --         --      --         --     --
  Nonproductive              1      0.5         --      --         --     --


(1)  Each well  completed to more than one producing zone is counted as a single
     well.  The  Company  has royalty  interests  in certain  wells that are not
     included in this table.

     In May 2003,  the  Company  arranged  with a private  investor  to fund the
drilling of two natural gas wells in the Arkoma  Basin of eastern  Oklahoma.  If
the wells are capable of  producing  natural gas in  commercial  quantities  the
Company will receive  approximately 5% of the production from the wells,  before

<PAGE>

payment of the  Company's  share of  operating  expenses,  until the investor is
repaid the amounts advanced to drill and complete the wells, which are estimated
to be $585,000.  After the amount advanced by the investor has been repaid,  the
Company will receive  approximately 25% of the production from the wells, before
payment of the Company's share of operating expenses.

GENERAL

     The  Company  has  never  been a  party  to any  bankruptcy,  receivership,
reorganization,  readjustment  or  similar  proceedings.  Since the  Company  is
engaged  in the oil and gas  business,  it does not  allocate  funds to  product
research and development in the  conventional  sense.  The Company does not have
any  patents,  trade-marks,  or  labor  contracts.  With  the  exception  of the
Company's  oil  and  gas  leases,  the  Company  does  not  have  any  licenses,
franchises,  concessions  or royalty  agreements.  Backlog is not material to an
understanding of the Company's  business.  The Company's business is not subject
to  renegotiation  of profits or termination of contracts or subcontracts at the
election of federal government.

EMPLOYEES

     At May 14, 2003,  the Company  employed  nine people in its  Oklahoma  City
office whose functions were associated with  management,  engineering,  geology,
land and legal, accounting, financial planning and administration.  In addition,
two part-time  employees were  responsible  for the supervision and operation of
the Company's field activities and providing well services.

ITEM 2.  DESCRIPTION OF PROPERTY

     The  following  table sets forth,  at January 31, 2003, by state and basin,
the Company's  producing  wells,  Developed  Acreage,  and Undeveloped  Acreage,
excluding service (injection and disposal) wells:

<TABLE>
<S>                             <C>            <C>      <C>           <C>        <C>           <C>


                                Productive Wells (1)    Developed Acreage     Undeveloped Acreage (2)
                                Gross          Net      Gross         Net        Gross         Net
                                -----         -----     -----        -----       -----        -----

Oklahoma (Arkoma Basin)            4           2.11     1,920      1,012.8          --           --
Wyoming (Powder River Basin)       2           .285        80         36.8    15,132.6     14,652.4

Totals                             6          2.395     2,000      1,049.6    15,132.6     14,652.4

</TABLE>


(1)  The wells in Oklahoma are gas wells and the wells in Wyoming are oil wells.
(2)  "Undeveloped  Acreage" includes leasehold interests on which wells have not
     been drilled or completed to the point that would permit the  production of
     commercial  quantities  of natural  gas and oil  regardless  of whether the
     leasehold interest is classified as containing proved undeveloped reserves.

     The following  table shows,  as of January 31, 2003 the status of Company's
gross developed and undeveloped acreage.


<PAGE>

      Gross Acreage           Held by Production     Not Held by Production

      Oklahoma                       1,920                      --
      Wyoming                          640                14,572.6

     Acres Held By Production  remain in force so long as oil or gas is produced
from  the well on the  particular  lease.  Leased  acres  which  are not Held By
Production  require annual rental payments to maintain the lease until the first
to occur of the following: the expiration of the lease or the time oil or gas is
produced from one or more wells drilled on the lease acreage. At the time oil or
gas is produced from wells drilled on the leased acreage the lease is considered
to be Held By Production.

        The Company does not own any Overriding Royalty Interests.

     Title to properties is subject to royalty, overriding royalty, carried, net
profits,  working  and other  similar  interests  and  contractual  arrangements
customary in the oil and gas  industry,  to liens for current  taxes not yet due
and to  other  encumbrances.  As is  customary  in the  industry  in the case of
undeveloped properties, little investigation of record title is made at the time
of  acquisition  (other than a preliminary  review of local  records).  Drilling
title opinions are always prepared before  commencement of drilling  operations;
however, as is customary in the industry.

     The following table sets forth the Company's net production of oil and gas,
average sales prices and average production costs during the periods presented:


                                                 Year Ended January 31,
Production Data:                            2001         2002          2003

Production - Oil (Bbls)                     473            498          403
Gas (Mcf)                                31,199         29,234       30,683
Average sales price -
Oil (Bbls)                              $ 27.34         $19.65       $26.08
Gas (Mcf)                               $  4.09        $  3.24      $  3.44
Average production
    costs per BOE                       $  4.97        $  2.93      $  4.79

     Production  costs  may vary  substantially  among  wells  depending  on the
methods of recovery employed and other factors,  but generally include severance
taxes, administrative overhead, maintenance and repair, labor and utilities.

     The Company is not obligated to provide a fixed and determined  quantity of
oil or gas in the future.  During the last three fiscal  years,  the Company has
not had, nor does it now have,  any long-term  supply or similar  agreement with
any government or governmental authority.

<PAGE>

     Below are estimates of the Company's net Proved Developed  Reserves and the
present value of estimated future net revenues from such Reserves based upon the
standardized  measure of discounted future net cash flows relating to proved oil
and gas Reserves in  accordance  with the  provisions  of Statement of Financial
Accounting   Standards  No.  69,   "Disclosures  about  Oil  and  Gas  Producing
Activities"  (SFAS No. 69). The  standardized  measure of discounted  future net
cash flows is  determined  by using  estimated  quantities  of Proved  Developed
Reserves and the periods in which they are expected to be developed and produced
based on period-end  economic  conditions.  The estimated  future  production is
priced  at  period-end  prices,   except  where  fixed  and  determinable  price
escalations  are  provided by  contract.  The  resulting  estimated  future cash
inflows  are then  reduced by  estimated  future  costs to develop  and  produce
reserves  based on  period-end  cost  levels.  No  deduction  has been  made for
depletion,  depreciation  or for  indirect  costs,  such  as  general  corporate
overhead. Present values were computed by discounting future net revenues by 10%
per year.

                                                   January 31,
                                   2001                 2002              2003
                              Oil      Gas         Oil    Gas       Oil      Gas
                            (Bbls)    (Mcf)       (Bbls) (Mcf)    (Bbls)   (Mcf)

Proved reserves             8,909    730,441     6,842  713,262   3,761  597,773
Estimated future net cash
  flows from proved oil and
    gas reserves                $1,519,467         $1,338,106       $2,147,220

Present value of future net
  cash flows from proved
  oil and gas reserves           $525,211           $493,982         $891,410

     As of May 14, 2003 the  Company's  wells in the Arkoma Basin  accounted for
approximately  95% of the Company's total oil and gas reserves and approximately
96% of the present value of the Company's  future net cash flow from its oil and
gas reserves.

     The Company's  Proved  Developed  Reserves include only those amounts which
the Company  reasonably  expects to recover in the future from known oil and gas
reservoirs under existing economic and operating  conditions,  at current prices
and costs,  under existing  regulatory  practices and with existing  technology.
Accordingly,   any  changes  in  prices,   operating  and   development   costs,
regulations,  technology  or  other  factors  could  significantly  increase  or
decrease estimates of Proved Developed Reserves.

     In general,  the volume of production  from natural gas and oil  properties
owned by the Company declines as reserves are depleted. Except to the extent the
Company acquires  additional  properties  containing proved reserves or conducts
successful exploration and development activities,  or both, the proved reserves
of the Company will decline as reserves are  produced.  Volumes  generated  from
future  activities of the Company are therefore  highly dependent upon the level
of success in acquiring or finding additional reserves and the costs incurred in
doing so.

<PAGE>

     In September 2000, the Company  relocated its offices to 800 Northeast 63rd
Street,  Oklahoma  City,  Oklahoma.  The 4,800  square  feet of office  space is
occupied under an unwritten lease, on a month-to-month  basis,  requiring rental
payments  of $3,800  per month.  The  building  is owned by George G. Shaw,  the
Company's Chief Executive Officer and a Director.

ITEM 3.  LEGAL PROCEEDINGS.

     From time to time,  the Company may be involved in  litigation  relating to
claims  arising out of its  operations  in the normal  course of  business.  The
Company is not currently a party to any pending legal proceedings.

     James Attarian,  a director and principal  shareholder of the Company,  has
advised the  Company  that in his opinion  the  Company  owes Mr.  Attarian  and
several companies  controlled by Mr. Attarian $300,000 to $400,000 more than the
$360,000 in loans which the Company has  recorded as loans to Mr.  Attarian  and
his  affiliates.  Dr.  Attarian  has  indicated  that his claims in this  regard
represent  amounts  paid by Dr.  Attarian and his  affiliates  for shares of the
Company's  stock and the drilling costs of unproductive  oil and gas wells.  The
Company  does not believe it owes any  material  amount to Dr.  Attarian and his
affiliated  entities  over and  above the  $360,000  which is  reflected  on the
Company's  balance  sheet at  January  31,  2003 as Due to Related  Parties  and
Shareholders.

ITEM 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

         Not Applicable

ITEM 5. MARKET PRICE OF AND  DIVIDENDS  ON THE  REGISTRANT'S  COMMON  EQUITY AND
OTHER SHAREHOLDER MATTERS.

Prior to May 7, 2003 the Company's common stock was traded listed on the Toronto
Venture  Exchange  under the symbol EEG. On March 3, 2003 the  Company's  common
stock was listed on the OTC Bulletin  Board under the symbol EGSR. The following
table sets forth the high and low sale prices of the  Company's  common stock in
U.S.  currency  during the periods  presented as reported by the Toronto Venture
Exchange. The closing sale prices reflect inter-dealer prices without adjustment
for  retail  markups,  markdowns  or  commissions  and  may not  reflect  actual
transactions.


                                              Closing Sale Price
                                                 Common Stock
            Quarter Ended                    High           Low

            April 30, 2001                   $0.19          $0.12
            July 31, 2001                    $0.25          $0.12
            October 31, 2001                 $0.25          $0.12
            January 31, 2002                 $0.16          $0.03

<PAGE>

            April 30, 2002                   $0.07          $0.04
            July 31, 2002                    $0.13          $0.03
            October 31, 2002                 $0.13          $0.03
            January 31, 2003                $ 0.11         $ 0.05

     On May 14,  2003,  there were  approximately  870 holders of the  Company's
common stock.

     The market price of the  Company's  common stock is subject to  significant
fluctuations in response to, and may be adversely  affected by (i) variations in
quarterly  operating  results,  (ii)  developments  in the oil and gas  industry
generally and more particularly  within the  geographically and geological areas
that the Company owns and operates  properties,  and (iii)  general stock market
conditions.

     The Company's common stock is subject to the "penny stock" rules. The penny
stock  trading  rules  impose  additional  duties  and   responsibilities   upon
broker-dealers  and  salespersons  recommending  the purchase or sale of a penny
stock.  Required  compliance with these rules will materially  limit or restrict
the ability to resell the Company's  common stock,  and the liquidity  typically
associated with other publicly traded stocks may not exist.

ITEM 6. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND PLAN OF
OPERATION

RESULTS OF OPERATIONS

     The  factors  that most  significantly  affect  the  Company's  results  of
operations are (i) the sale prices of crude oil and natural gas, (ii) the amount
of production sales, (iii) the amount of lease operating expenses,  and (iv) the
level of interest rates on, and amount of,  borrowings.  Sales of production and
level of  borrowings  are  significantly  impacted by the  Company's  ability to
maintain or increase its production from existing oil and gas properties through
its  exploration and  development  activities.  The following table reflects the
average prices  received by the Company for oil and gas, the average  production
cost per BOE, and the amount of oil and gas produced for the periods presented:

                                           Year Ended January 31,
Production Data:                     2001           2002           2003

Production - Oil (Bbls)               473             498           403
Gas (Mcf)                          31,199          29,234        30,683
Average sales price -
   Oil (Bbls)                     $ 27.34         $ 19.65       $ 26.08
Gas (Mcf)                         $  4.09         $  3.24       $  3.44
Average production
    costs per BOE                 $  4.97         $  2.93       $  4.79

<PAGE>

     Prices  received by the Company for sales of crude oil and natural gas have
fluctuated  significantly  from period to period. The fluctuations in oil prices
during these periods reflect market  uncertainty  regarding the inability of the
Organization of Petroleum Exporting Countries ("OPEC") to control the production
of its member  countries,  as well as concerns  related to the global supply and
demand for crude oil. Gas prices received by the Company  fluctuate with changes
in the spot market price for gas, which reached recent record levels in December
2000 in the United  States.  This price  increase was due to demand in excess of
deliverability and higher worldwide energy prices.

     Changes in natural gas and crude oil prices will  significantly  affect the
revenues and cash flow of the wells and the value of the oil and gas properties.
Declines  in the  prices of crude oil and  natural  gas  could  have a  material
adverse  effect on the  success  of the  Company's  operations  and  activities,
recoupment of the costs of acquiring, developing and producing the its wells and
profitability.  The Company is unable to predict whether the prices of crude oil
and natural gas will rise, stabilize or decline in the future.

     Other than the foregoing,  the Company does not know of any trends,  events
or  uncertainties  that have had or are  reasonably  expected to have a material
impact on the Company's net sales, revenues or expenses.

YEAR ENDED JANUARY 31, 2003

     Material changes of certain items in the Company's  Statement of Operations
for the year ended  January 31, 2003,  as compared to the same period last year,
are discussed below:

                           Increase (I)
Item                    or Decrease (D)   Reason

Oil and Gas Sales               I         Increase in the price of oil and gas.
Salaries and Benefits           D         Temporary staff was eliminated and the
                                          compensation paid to some employees
                                          was reduced.
Legal and Accounting            D         Less costs associated with amending
                                          the Company's registration statement
                                          on Form 10-SB.
Rent                            I         Off-site space was used for part of
                                          the year to store some of the
                                          Company's records and equipment,
                                          plus rent due in the prior year was
                                          paid in the current year.
Office and General Expense      D         Office expenses were reduced to
                                          conserve cash.
Pipeline Costs                  I         Duke Energy increased the charges for
                                          transporting gas through its pipeline.
Interest                        D         Settlement of debt since October 2001
                                          resulted in less interest expense
                                          during the current year.
<PAGE>


YEAR ENDED JANUARY 31, 2002

     Material changes of certain items in the Company's  Statement of Operations
for the year ended  January 31, 2002,  as compared to the same period last year,
are discussed below:

                                  Increase (I)
Item                          or Decrease (D)   Reason

Oil and Gas Sales                     D         Decline in oil and gas prices.
Pipeline Revenue                      I         Increased production resulted in
                                                more gas transported through the
                                                Company's gas gathering system.
Salaries and Benefits                 I         Temporary staff hired to assist
                                                with filings with the Securities
                                                and Exchange Commission.
Depreciation and Depletion            I         Adjustment made during the
                                                current nine-month period to
                                                conform the Company's depletion
                                                rate to its proven oil and gas
                                                reserves.
Legal and Accounting                  I         Costs related to preparing the
                                                Company's Registration Statement
                                                on Form 10-SB and additional
                                                auditing expense.
Rent                                  D         Relocation of office to space
                                                with less expense lease.
Business Investigation Costs          D         Business investigation costs
                                                during the prior period 2001
                                                related to the unsuccessful
                                                attempt to acquire oil and gas
                                                properties from the G.M. Oil
                                                Company.
Consulting                            I         Consulting expenses increased
                                                slightly due to increased
                                                amounts paid to a consultant to
                                               be competitive with market rates.
Office and General Expense            I         The Company's offices were
                                                vandalized in November 2000.
                                                Costs increased due to required
                                                repairs and cleaning subsequent
                                                to January 31, 2001.
Travel and Promotion                  D         Less travel to inspect wells in
                                                Wyoming.
Interest Expense                      I         Interest bearing debt was higher
                                                during the current period.

<PAGE>



OIL AND GAS PRICE FLUCTUATIONS

     Fluctuations  in  crude  oil and  natural  gas  prices  have  significantly
affected the Company's  operations  and the value of its assets.  As a result of
the  instability and volatility of crude oil and natural gas prices and at times
the market  conditions within the oil and gas industry,  financial  institutions
are  selective in the energy  lending area and have  reduced the  percentage  of
existing  reserves  that may qualify for the  borrowing  base to support  energy
loans.

     The Company's  principal  source of cash flow is the production and sale of
its crude oil and natural gas reserves  which are  depleting  assets.  Cash flow
from oil and gas  production  sales depends upon the quantity of production  and
the price  obtained  for such  production.  An  increase  in prices  permits the
Company to finance its operations to a greater extent with internally  generated
funds, may allow the Company to obtain equity financing more easily or on better
terms, and lessens the difficulty of attracting financing from industry partners
and non-industry  investors.  However,  price increases heighten the competition
for Leases and  Prospects,  increase the costs of  exploration  and  development
activities,  and,  because  of  potential  price  declines,  increase  the risks
associated  with the purchase of Producing  Properties  during times that prices
are at higher levels.

     A decline  in oil and gas  prices  (i)  reduces  the cash  flow  internally
generated by the Company which in turn reduces the funds available for servicing
debt and exploring for and  replacing oil and gas reserves,  (ii)  increases the
difficulty of obtaining equity and debt financing and worsens the terms on which
such financing may be obtained, (iii) reduces the number of Leases and Prospects
which  have  reasonable  economic  terms,  (iv) may cause the  Company to permit
Leases to expire  based  upon the value of  potential  oil and gas  reserves  in
relation to the costs of exploration,  (v) results in marginally  productive oil
and gas  wells  being  abandoned  as  non-commercial,  and  (vi)  increases  the
difficulty  of attracting  financing  from  industry  partners and  non-industry
investors.  However,  price  declines  reduce  the  competition  for  Leases and
Prospects and  correspondingly  reduce the prices paid for Leases and Prospects.
Furthermore,  exploration and production costs generally  decline,  although the
decline may not be at the same rate as that of oil and gas prices.

     The Company's  results of operations are somewhat  seasonal due to seasonal
fluctuations in the sales prices for natural gas. Although in recent years crude
oil prices have been generally  higher in the third and fourth fiscal  quarters,
these fluctuations are not believed to be seasonal. Natural gas prices have been
generally higher in the fourth fiscal quarter.

CAPITAL RESOURCES AND LIQUIDITY

     The  following is an  explanation  of the  Company's  material  sources and
(uses) of cash during the year ended January 31, 2003:

      Cash on hand at February 1, 2002                     $     2,054
      Cash used in operations                                 (364,535)
      Loans from shareholder, related parties and investor     440,544
      Reduction of notes payable                               (25,458)
      Other                                                    (31,222)

      Cash on hand at January 31, 2003                          21,383

<PAGE>

     The  following is an  explanation  of the  Company's  material  sources and
(uses) of cash during the year ended January 31, 2002:

      Cash on hand at February 1, 2001               $22,547
      Cash used in operations                       (491,565)
      Payment of shareholder loans                  (120,644)
      Sale of common stock and warrants              580,295
      Other                                           11,422

      Cash on hand at January 31, 2002              $  2,054

     As a result of the  Company's  continued  losses  and lack of cash there is
substantial  doubt as to the  Company's  ability  to  continue  operations.  The
Company  plans to  generate  profits by  drilling  productive  oil or gas wells.
However,  the Company  will need to raise the funds  required to drill new wells
from third parties willing to pay the Company's share of drilling and completing
the wells.  The Company may also  attempt to raise  needed  capital  through the
private sale of its securities or by borrowing  from third parties.  The Company
may not be successful  in raising the capital  needed to drill oil or gas wells.
In  addition,  any future  wells  which may be drilled by the Company may not be
productive of oil or gas. The  inability of the Company to generate  profits may
force the Company to curtail or cease operations.

     During the years ended January 31, 2003 and 2002, the Company did not spend
any  amounts  on oil and gas  exploration  and  did not  acquire  any oil or gas
properties.  The lack of capital expenditures during the years ended January 31,
2003 and 2002 was  primarily  the result of the  Company's  inability to conduct
exploration activities during these periods due to a lack of funds.

     As of May  14,  2003,  the  Company  did  not  have  any  material  capital
commitments,  other than funding its operating  losses and repaying  outstanding
debt.  It is  anticipated  that any capital  commitments  that may occur will be
financed  principally  through borrowings from institutional and private lenders
(although  such  additional  financing  has not been  arranged)  and the sale of
shares of the Company's common stock or other equity securities.  However, there
can be no assurance that  additional  capital  resources and financings  will be
available  to the Company on a timely  basis,  or if  available,  on  acceptable
terms.

     As of January  31,  2003 the Company  had  outstanding  loans to  officers,
directors and others of approximately $1,042,000. See Item 12 of this report for
information  concerning  these  loans.  As of this same date the Company did not
have sufficient funds to pay these liabilites.  The Company plans to repay these
loans  from  the sale of oil or gas  from  wells  which  may be  drilled  by the
Company, if sufficient capital is available,  or from the proceeds received from
the sale of the  Company's  capital  stock.  Mr. Shaw,  to whom the Company owed
approximately  $493,500 as of January 31, 2003,  has advised the Company that he
will not look for  repayment of the amounts owed to him by the Company  prior to
December 31, 2003.  The other  lenders may at any time file a lawsuit to enforce
the collection of the amounts owed by the Company.

<PAGE>


ITEM 7.  FINANCIAL STATEMENTS

      See the financial statements attached to this report.

ITEM 8.  CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS.

     Effective  January 24, 2002 the Company  retained  Spicer,  Jefferies & Co.
("Spicer") to act as the Company's independent  certified public accountant.  In
this regard  Spicer  replaced  Bedford  Curry & Co. which  audited the Company's
financial statements for the fiscal years ended January 31, 2001, 2000 and 1999.
The report of Bedford  Curry for these  fiscal  years did not contain an adverse
opinion, or disclaimer of opinion and were not qualified or modified as to audit
scope or accounting  principles.  However, the report of Bedford Curry for these
fiscal years was  qualified  with  respect to  uncertainty  as to the  Company's
ability to continue as a going concern.  During the Company's  three most recent
fiscal years and the subsequent interim period ended January 24, 2002 there were
no  disagreements  with Bedford Curry on any matter of accounting  principles or
practices, financial statement disclosure or auditing scope or procedures, which
disagreements,  if not resolved to the  satisfaction of Bedford Curry would have
caused it to make reference to such disagreements in its reports.

     Bedford  Curry  is  based  in  Vancouver,  British  Columbia.  The  Company
dismissed  Bedford Curry due to rules of the Securities and Exchange  Commission
which require the Company's  financial  statements to be audited by  accountants
that are based in the United States. The Company has authorized Bedford Curry to
discuss any matter relating to the Company and its operations with Spicer.

     The change in the Company's  auditors was  recommended  and approved by the
Company's board of directors.

     During the two most recent fiscal years and subsequent interim period ended
January  24,  2002,  the  Company did not  consult  with  Spicer  regarding  the
application  of  accounting  principles  to  a  specified  transaction,   either
completed  or proposed,  or the type of audit  opinion that might be rendered on
the  Company's  financial  statements,  or any matter  that was the subject of a
disagreement  or a  reportable  event  as  defined  in  the  regulations  of the
Securities and Exchange Commission.

ITEM 9. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS

     The  following  table sets forth  information  with  respect to each of the
Company's  executive  officers and  directors as of May 14, 2003.  The Company's
directors are  generally  elected at the annual  shareholders'  meeting and hold
office until the next annual shareholders' meeting or until their successors are
elected and qualified. The Company's executive officers are elected by our board
of directors and serve at its discretion.

<PAGE>



Name                         Age       Position

George G. Shaw               72        President and Chief Executive Officer and
                                       Chairman of the Board
G. Scott Shaw                32        Vice President, Secretary and a Director
David W. Young               53        Chief Financial Officer and a Director
James H. Attarian, M.D.      43        Director

     The  following is a brief  description  of the business  background  of the
Company's executive officers and directors:

     GEORGE G. SHAW is the President,  Chief  Executive  Officer and Chairman of
the Board of  directors of the Company and has held these  positions  since July
1991.  Mr.  Shaw is the  President  of Energas  Corporation  and its  subsidiary
Energas Pipeline Co., Inc., both privately held companies engaged in oil and gas
exploration and gas gathering. Mr. Shaw is the father of G. Scott Shaw.

     G. SCOTT SHAW is the Vice  President  and a director of the Company and has
held these positions since August 1996. Mr. Shaw became the Company's  Secretary
in April 2003. Mr. Shaw graduated from Oklahoma State  University in 1993 with a
Bachelor of Science degree in Biology. Mr. Shaw is the son of George G. Shaw.

     DAVID W.  YOUNG has held the  position  of Chief  Financial  Officer of the
Company  since April 1995.  Mr.  Young has been a director of the Company  since
August 2001.  Mr. Young is a practicing  accountant  and was graduated  from the
University of Central Oklahoma in 1975, with a B.B.S. in accounting.

     JAMES H.  ATTARIAN,  M.D.  became a director of the company in August 2001.
Dr.  Attarian has been a practicing  physician  since  February  1994. He is the
managing  member of Mankato  Investments  LLC and  Jurassic  Capital  LLC,  both
privately-held  investment companies. Dr. Attarian received a B.S. in 1983 and a
M.D. in 1987 from the University of Michigan.

     As of November  30, 2002 George  Shaw,  David Young and Dr.  Attarian  were
members of the Company's Audit Committee.

ITEM 10.  EXECUTIVE COMPENSATION

     The  following  table sets forth the  compensation  during the years  ended
January  31,  2003,  2002 and 2001,  paid or  accrued,  to George G.  Shaw,  the
Company's  Chief  Executive  Officer  during those years.  None of the Company's
executive officers received  compensation in excess of $100,000 during the three
years ended January 31, 2003.

<PAGE>



                                                                     Long-Term
                                                                   Compensation
                                                                      Awards
                                                                    Common Stock
                                Year Ended    Annual Compensation    Underlying
Name and Principal Position     January 31,  Salary (2)   Bonus (3)   Options

George G. Shaw                     2003     $33,000       --             --
   President and Chief
   Executive Officer               2002     $33,000       --             --
                                   2001     $33,000       --             --

(1)  The named executive  officer  received  additional  non-cash  compensation,
     perquisites and other personal benefits;  however, the aggregate amount and
     value  thereof did not exceed 10% of the total annual salary and bonus paid
     to and accrued for the named executive officer during the year.
(2)  Dollar  value of base salary  (both cash and  non-cash)  earned  during the
     year.
(3)  Dollar value of bonus (both cash and non-cash) earned during the year.

     The  following  shows the amounts  which the Company  expects to pay to its
officers  during the twelve month period ending  January 31, 2004,  and the time
which the Company's executive officers plan to devote to the Company's business.
The Company does not have employment agreements with any of its officers.

                                   Proposed              Time to Be Devoted
Name                          Compensation            To Company's Business

George G. Shaw                    $60,000                      100%
G. Scott Shaw                     $42,000                      100%
David W. Young                   $  6,000                       10%

AGGREGATE OPTION GRANTS AND EXERCISES IN YEAR ENDED JANUARY 31, 2003
AND YEAR-END OPTION VALUES

     During the year ended  January 31, 2003 the Company did not grant any stock
options or warrants to its  executive  officers  or  directors.  During the year
ended January 31, 2003 none of the Company's officers or directors exercised any
options or warrants.  As of January 31, 2003 none of the  Company's  officers or
directors  held any  options or  options.  Subsequent  to January  31,  2003 the
Company did not issue any options or warrants.

EMPLOYMENT AGREEMENTS AND KEYMAN INSURANCE

     The Company does not have any  employment  agreements  with its officers or
employees.  The Company does not maintain any keyman insurance on the life or in
the event of disability of any of its officers.

<PAGE>


ITEM 11.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

     The following table presents,  as of May 14, 2003,  information  related to
the beneficial ownership of the Company's common stock of (i) each person who is
known  to us to be the  beneficial  owner  of more  than  5%,  (ii)  each of our
directors and executive  officers,  and (iii) all of our executive  officers and
directors as a group.  All persons listed have sole voting and investment  power
with respect to their shares unless otherwise indicated, and there are no family
relationships among the Company's executive officers and directors,  except that
George G. Shaw is the father of G. Scott Shaw.  For  purposes  of the  following
table,  the number of shares and percent of  ownership of the  Company's  common
stock that the named person  beneficially  owns includes shares of the Company's
common stock that the person has the right to acquire on or before July 31, 2003
from exercise of stock options or otherwise.

                                                   Shares           Percent of
                                                Beneficially      Outstanding
Name and address                                   Owned              Shares

George G. Shaw
Third Floor, 800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105                  7,070,236 (1)             27%

James H. Attarian, M.D.
230 East Main Street
Mankato, Minnesota 56002-8674                  2,900,450 (2)           10.9%

G. Scott Shaw                                     60,000                  *
800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105

David W. Young                                        --                 --
800 Northeast 63rd Street
Oklahoma City, Oklahoma 73105

Clare LLC
401 South LaSalle, Suite 302
Chicago, Illinois 60605                        2,000,000               7.7%

Executive Officers and Directors as a group
 (four persons)                               10,030,686                39%

* The  shares  beneficially  owned  represent  less  than 1% of the  outstanding
shares.

(1)  Includes  (i)  2,444,916  shares  held  by  Energas  Corporation  of  which
     1,759,680 of these shares are subject to a time-release  escrow  agreement,
     and (ii) 3,460,320 shares held by Energas Pipeline Co., Inc. are subject to
     a time-based  escrow  agreement and (iii) 1,585,000  shares of common stock
     held by Mr.  Shaw.  The shares  held under the  escrow  agreements  will be
     released from escrow in 12 six month  installments  commencing on March 21,

<PAGE>

     2002  (initially  four  installments  of  290,000  shares of  common  stock
     followed by eight installments of 580,000 shares of common stock). Mr. Shaw
     controls Energas Corporation and Energas Pipeline Co., Inc.

(2)  The  beneficially  owned shares and the  percentage  include (i)  1,405,675
     shares of common stock held by Mankato Investments LLC, (ii) 384,550 shares
     of common stock held by Jurassic Capital LLC, and (iii) 450,000 shares held
     by Dr. Attarian. Dr. Attarian controls Mankato Investments LLC and Jurassic
     Capital LLC.

ITEM 12.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

     In December  2000,  Mankato  Investments  LLC purchased  275,675  shares of
common stock and common stock purchase warrants  exercisable for the purchase of
275,675  shares of common  stock  for $.33 per share on or before  December  21,
2002. The Company  received  proceeds from this sale of $60,350.  In April 2001,
Jurassic  Capital LLC purchased  384,550 shares of common stock and common stock
purchase warrants exercisable for the purchase of 384,550 shares of common stock
for $.195 per share on or before April 11, 2003. The Company  received  proceeds
from this sale of $74,733.  Mankato Investments LLC and Jurassic Capital LLC are
controlled by James H. Attarian, a director and principal shareholder.

     In February 1999 the Company borrowed $300,000 from Mankato Investments LLC
to fund lease acquisitions and the exploration and development. The loan was due
April 1, 2002 and  beginning  April 1, 2002 the loan bears  interest  at 12% per
year. As of August 31, 2002 this loan was in default.  As partial  consideration
for this loan, the Company issued  warrants for the purchase of 60,000 shares of
the Company's  common stock at a price of $0.27 per share.  These  warrants were
exercised in September 2000.

     During the year ended  January 31, 2001,  the Company  received  additional
loans of $60,000 from Mankato  Investments  LLC. The loan proceeds were used for
operating expenses.  The loans are non-interest  bearing,  were due May 13, 2002
and are in default.  As of May 14, 2003 Mankato  Investments  had not instituted
proceedings to collect the amounts owed by the Company.

     In September  2000,  the Company  relocated its offices to the third floor,
800 Northeast 63rd Street, Oklahoma City, Oklahoma. The office space is occupied
under an unwritten  month-to-month lease requiring rental payments of $3,800 per
month to Mr. Shaw, the owner of the building. During the years ended January 31,
2002 and 2001 the Company  paid rent of $40,797 and  $20,520,  respectively.  In
addition,  Mr. Shaw owns Energas  Pipeline Company that operates the natural gas
gathering system to which the Company's four wells in Atoka County, Oklahoma are
connected.  During the years ended  January  31,  2003,  2002 and 2001,  Energas
Pipeline Company received $14,428,  $13,765 and $12,466,  respectively,  for its
services in operating the gathering system.

     As of January 31, 2003 the Company had borrowed approximately $493,500 from
George Shaw and entities  controlled  by Mr. Shaw.  These loans is  non-interest
bearing,  unsecured,  and do not have  fixed  terms of  repayment.  The  amounts
borrowed  from  Mr.  Shaw and his  affiliates  were  used to fund the  Company's
operations.

<PAGE>

     See Item 3 of this report for  information  concerning a claim of Dr. James
Attarian.

     During the year ended January 31, 2002 the Company issued 400,070 shares of
its common stock to Mankato  Investments LLC in payment of $138,800  advanced to
the Company by Mankato Investments. The $138,800 in advances were in addition to
the $360,000 owed by the Company to Mankato.

     The  Company  believes  that the legal fees paid Lang  Michener  Lawrence &
Shaw, the rent paid to Mr. Shaw and the terms of the other transactions  between
the  Company  and its  officers  and  directors  discussed  above  were fair and
reasonable  and were upon terms as least as favorable as the Company  could have
obtained from unrelated third parties.

     Transactions  with  the  Company's  officers,   directors,   and  principal
shareholders  may continue  and may result in conflicts of interest  between the
Company and these  individuals.  Although these persons have fiduciary duties to
the Company and its  shareholders,  there can be no assurance  that conflicts of
interest  will  always be  resolved  in favor of Company  and its  shareholders.
Neither  the  Company's   Articles  of  Incorporation  nor  Bylaws  contain  any
provisions for resolving potential or actual conflicts of interest.

ITEM 13.  EXHIBITS AND REPORTS ON FORM 8-K

Exhibits

Exhibit No.  Description of Exhibit                               Page Number

3.1          Certificate of Incorporation                               *

3.2          Bylaws                                                     *

3.3          Certificate of Domestication in Delaware                   *

4.1          Form of Certificate of Common Stock of Registrant          *

4.2          Warrant Agreement, dated September 10, 1999
             between Registrant and MEDICOMP.                           *

4.3          Warrant Agreement, dated October 8, 1999 between
             Registrant and Mankato  Investments, LLC                   *

4.4          Warrant Agreement, dated December 13, 2000 between
             Registrant and Mankato Investments, LLC                    *

4.5          Warrant Agreement, dated March 5, 2001 between
             Registrant and Jurassic Capital LLC                        *

<PAGE>


Exhibit No.  Description of Exhibit                               Page Number

4.6          Escrow Amendment Agreement amongst Registrant,
             Pacific Corporate Trust Company, Energas
             Corporation and Energas Pipeline Company                   *

4.7          Escrow Agreement, dated September 20, 1991,
             amongst Registrant, Pacific Corporate Trust
             Company, Energas Corporation and Energas
             Pipeline Company                                           *

4.8          Registration Rights Agreement, dated July 18, 2001
             between Registrant and Clare, LLC                          *

4.9          Escrow Amendment Agreement, dated April 13, 1994,
             amongst Registrant, Pacific Corporate Trust Company,
             Energas Corporation and Energas Pipeline Company           *

10.1        Stock Purchase Agreement, dated August 26, 2000,
            amongst Registrant, Larry G. Jordan, Jim and Billie
            Baker, Keith D. Menees, Williard L. and Jeanne
            O'Daniel, James W. and Lacada Greer Living Trust,
            Jack Marie Sellers, and Mark R. Hoy.                        *

10.2        Amendment to Stock Purchase Agreement,  dated
            September 23, 2000, amongst Registrant, Larry G. Jordan,
            Jim and Billie Baker, Keith D. Menees,  Williard
            L. and Jeanne  O'Daniel,  James W. and Lacada Greer
            Living Trust, Jack Marie Sellers, and Mark R. Hoy.          *

10.3        Second Amendment to Stock Purchase Agreement,
            dated October 30, 2000, amongst amongst Registrant,
            Larry G. Jordan, Jim and Billie Baker, Keith
            D. Menees,  Williard L. and Jeanne O'Daniel,
            James W. and Lacada Greer Living Trust, Jack Marie
            Sellers, and Mark R. Hoy.                                   *

10.4        Third Amendment to Stock Purchase  Agreement,
            dated November 8, 2000, amongst amongst
            Registrant,  Larry G.  Jordan,  Jim and  Billie
            Baker,  Keith D. Menees,  Williard  L. and
            Jeanne  O'Daniel,  James W. and Lacada
            Greer Living Trust, Jack Marie Sellers, and Mark R. Hoy.   *

10.5        Escrow Agreement,  dated November 8, 2000,  amongst
            Registrant,  BancFirst,  Larry G.  Jordan,  Jim and
            Billie  Baker,  Keith D. Menees,  Willard L. and
            Jeanned  O'Daniel,  James W. and Lavada Greer Living
            Trust,  Jack Marie Sellers, Mark R. Hoy and First
            Natural Gas, Inc.                                           *

<PAGE>


Exhibit No.  Description of Exhibit                               Page Number

10.6        Form of  Promissory  Note issued to
            Larry G. Jordan,  Jim and Billie  Baker,  Keith D.
            Menees,  Larry and Jeanne  O'Daniel,  James W.
            and  Lavada  Greer Living Trust, Jack Marie
            Sellers, and Mark R. Hoy.                                   *

10.7        Gas Purchase  Agreement,  dated March 1, 1991
            between  Registrant and Energas Pipeline
            Company.                                                    *

10.8        Gas Purchase  Agreement,  dated March 1, 1991
            between  Registrant and Energas Pipeline
            Company.                                                    *

10.9        Gas Gathering  Agreement,  dated July 1, 1992
            between Energas Pipeline  Company,  Inc.
            and A.T. Gas Gathering Systems, Inc.                        *

10.10       Gas Purchase  Agreement,  dated February 13, 1997,
            between  Panenergy Field Services,
            Inc. and Energas Pipeline Company.                          *

10.11       Gas  Purchase  Agreement,  dated  October 1, 1999,
            between  Registrant  and Ozark Gas
            Gathering, L.L.C.                                           *

10.12       Letter agreement, dated December 30, 1996,
            between  Registrant and Conoco, Inc.                        *

10.13       Promissory Note ($25,000) payable to Craig
            and Karen Aubuchon                                          **

10.14       Promissory Note ($50,000) payable to Mark Swan              **

10.15       Loan Agreement ($300,000) with Mankato Investments LLC      **

10.16       Promissory Note ($60,000) payable to Mankato
            Investments LLC                                             **

16.         Letter regarding change in certifying public accountant.   **

21.         Registrant's Subsidiaries                                   *

*  Incorporated  by  referenced  to the same  exhibit  filed with the  Company's
initial registration statement on Form 10-SB.

**  Incorporated  by reference to the same exhibit filed with Amendment No. 1 to
the Company's registration statement on Form 10-SB

     During the three months ended January 31, 2003 the Company did not file any
reports on Form 8-K.

ITEM 14.  CONTROLS AND PROCEDURES

     George Shaw, the Company's Chief Executive  Officer and David W. Young, the
Company's  Chief  Financial  Officer,  have evaluated the  effectiveness  of the
Company's  disclosure  controls and procedures as of a date within 90 days prior
to the filing date of this report (the "Evaluation  Date"); and in their opinion
the  Company's   disclosure   controls  and  procedures   ensure  that  material
information relating to the Company, including its consolidated subsidiaries, is
made known to them by others  within  those  entities,  particularly  during the
period in which this report is being prepared,  so as to allow timely  decisions
regarding required disclosure.  To the knowledge of Mr. Shaw and Mr. Young there
have been no significant  changes in the Company's internal controls or in other
factors  that  could  significantly   affect  the  Company's  internal  controls
subsequent  to the  Evaluation  Date. As a result,  no  corrective  actions with
regard  to  significant  deficiencies  or  material  weakness  in the  Company's
internal controls were required.


<PAGE>


                                             ENERGAS RESOURCES INC.

                                        CONSOLIDATED FINANCIAL STATEMENTS

                                            JANUARY 31, 2003 AND 2002














<PAGE>




                             ENERGAS RESOURCES INC.

                                    CONTENTS



                                                                     Page

Independent Auditors' Report                                           1

Consolidated Balance Sheets as of January 31, 2003 and 2002            2

Consolidated Statements of Operations for the years ended
   January 31, 2003 and 2002                                           3

Consolidated Statements of Stockholders' (Deficit) for the
   years ended January 31, 2003 and 2002                               4

Consolidated Statements of Cash Flows for the years ended
    January 31, 2003 and 2002                                          5

Notes to Consolidated Financial Statements for the years ended
    January 31, 2003 and 2002                                       6 - 12




<PAGE>











                          INDEPENDENT AUDITORS' REPORT









To the Board of Directors
Energas Resources Inc.

We have audited the consolidated balance sheets of Energas Resources, Inc. as of
January 31, 2003 and 2002 and the consolidated statements of operations,
stockholders' (deficit) and cash flows for the years then ended. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of Energas Resources, Inc. as of
January 31, 2003 and 2002 and the results of its operations and its cash flows
for the years then ended in accordance with accounting principles generally
accepted in the United States of America.

The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company has not generated sufficient cash flows from
operations and has suffered operating losses since inception. These conditions
raise substantial doubt about its ability to continue as a going concern.
Management's plans in this regard are also discussed in Note 1. The financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.




Denver, Colorado
April 23,  2003



<PAGE>




                             ENERGAS RESOURCES, INC.

                           CONSOLIDATED BALANCE SHEETS

                            January 31, 2003 and 2002

                                                            2003          2002
                          ASSETS
Cash                                                    $   21,383    $   2,054
Accounts receivable                                            700        6,792
Prepaid expenses                                                --          214
                                                        ----------  -----------

   Total current assets                                     22,083        9,060
                                                        ----------  ------------


Property and equipment, net(Note 3)                        505,595      505,258

Other assets                                                    --        4,132
                                                      ------------  ------------
                                                         $ 527,678   $  518,450
                                                      ============  ============

 LIABILITIES AND STOCKHOLDERS' (DEFICIT)

Current
liabilities
    Accounts payable and accrued expenses               $  270,002    $ 201,380
    Due to related parties and                           1,007,404      374,860
    shareholders (Note 7)
    Investor advance payable (Note 8)                      168,000           --
    Note payable (Note 4)                                   34,542       50,000
                                                       -----------  ------------

      Total current liabilities                          1,479,948      626,240
                                                      ------------  ------------

Long-term debt
  Note payable to shareholder(Note 7):
    Principal amount                                            --      360,000
    Less unamortized discount                                   --       (2,312)
                                                        ----------  -----------
    Long-term debt less unamortized discount                    --      357,688
                                                      ------------  ------------

Contingencies (Note 10)

                 STOCKHOLDERS' (DEFICIT)

Common stock, $.001 par value, 100,000,000 shares
   authorized, 26,143,001 shares issued and
   outstanding                                              26,143       26,143
Additional Paid in Capital                               7,621,777    7,621,777
Deficit                                                 (8,600,190)  (8,113,398)
                                                      ------------  ------------
                                                          (952,270)    (465,478)
                                                       ------------   ----------

                                                       $   527,678   $  518,450
                                                      ============   ===========




<PAGE>


                             ENERGAS RESOURCES, INC.

                      CONSOLIDATED STATEMENTS OF OPERATIONS


                                                      Year ended
                                                     January 31,
                                                       2003             2002
                                                   -------------    -----------

REVENUE

Oil and gas sales                                 $    116,031      $  104,411

Pipeline revenue                                        15,808          15,542
Gain on disposal of assets                                  --          16,061
Gain from debt refinancing                              10,904              --
                                                  -------------    -------------

                                                       142,743         136,014
                                                  -------------    -------------

EXPENSES

Salaries and benefits                                  254,567         335,847
Depreciation and depletion                              30,885          38,192
Legal and accounting                                    86,637         123,060
Write-down of oil and gas properties                        --           6,665
Rent                                                    61,803          45,477
Oil and gas production                                  26,544          23,119
Consulting                                              32,682          31,983
Office and general                                      28,622          61,703
Travel and promotion                                    16,530          11,549
Telephone                                               17,924          18,525
Regulatory fees                                          6,952           4,119
Pipeline costs                                          20,793           3,292
Interest expense                                        45,596          50,864
                                                  -------------    -------------

                                                       629,535         754,395
                                                  -------------    -------------

NET LOSS                                           $  (486,792)    $  (618,381)
                                                  =============    =============

LOSS PER SHARE - BASIC AND DILUTED                  $    (0.02)    $     (0.03)
                                                  =============    =============

WEIGHTED AVERAGE SHARES OUTSTANDING                 26,143,001      24,400,598
                                                  =============    =============




<PAGE>



                             ENERGAS RESOURCES, INC.

                CONSOLIDATED STATEMENTS OF STOCKHOLDERS' (DEFICIT)

                      Years ended January 31, 2003 and 2002


                                                       Additional
                              Common Stock               Paid In     Accumulated
                                 Shares       Amount     Capital      Deficit
                              --------------------------------------------------
Balances, January 31,
  2001                        22,459,153     $22,459   $6,828,342    (7,495,017)

    Common stock issued for:
      Private placements       2,384,550       2,385      462,910
      Warrants exercised         500,000         500      114,500
      Settlement of debt         799,298         799      216,025

    Net loss                                                           (618,381)
                             --------------------------------------------------
Balances, January 31,
  2002                        26,143,001      26,143    7,621,777    (8,113,398)

    Net loss                                                           (486,792)
                              --------------------------------------------------

Balances, January 31,
  2003                        26,143,001      $26,143  $7,621,777   $(8,600,190)
                             ==================================================





<PAGE>


                             ENERGAS RESOURCES, INC.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS

                      Years ended January 31, 2003 and 2002

                                                            2003         2002
                                                        -----------   ---------
Cash flows from operating activities
Net loss                                               $ (486,792)    $(618,381)
Add items not involving cash
          Depreciation and depletion                       30,885        38,192
          Amortization of discount and
            debt issue cost                                 2,444        44,285
          Write-down of oil and gas properties                 --         6,665
          Gain on settlement of past due
             note payable                                 (10,904)           --
          Gain on involutary conversion
             of assets                                         --       (16,061)

Change in non-cash working capital balances
   related to operations
          Increase in accounts payable and accrued
              expenses                                     89,526        47,400
          Decrease in prepaid expenses                        214         2,205
          Decrease (Increase) in other assets               4,000        (4,000)
          Decrease in accounts receivable                   6,092         8,130
                                                        ---------     ---------
          Net Cash Used in Operating Activities          (364,535)     (491,565)
                                                       -----------    ---------

Cash Flows from Financing Activities
Shares issued for:
          Private placement                                    --       465,295
          Warrants                                             --       115,000
Increase (decrease) in due to Related parties             272,544      (120,644)
Payments on notes payable                                 (25,458)
                                                      -----------     ---------
          Net Cash Provided By Financing Actvities        247,086       459,651
                                                      -----------     ---------

Cash Flows From Investing Activities
Purchase of property and equipment                       (31,222)       (14,225)
Proceeds from investor advance                           168,000
Proceeds from involuntary conversion of assets                --         25,646
                                                     -----------      ---------
          Net Cash Provided by Investing
            Activities                                   136,778         11,421
                                                     -----------      ---------

Increase (decrease) in cash                               19,329        (20,493)
Cash, beginning of year                                    2,054         22,547
                                                     -----------       ---------

Cash, end of year                                     $   21,383     $    2,054
                                                      ===========    ==========

Supplemental Cash Flow Information
Cash paid for interest                                $    3,292     $       --
                                                      ===========    ==========

Supplemental Disclosure of Non-cash Investing and
Financing Activities:

      Issuance of stock for settlement of debt                --       $216,824
                                                      ===========     =========
      Settlement of accrued interest for note payable     10,000             --
                                                      ===========     =========



<PAGE>


                             Energas Resources Inc.

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

                      Years ended January 31, 2003 and 2002

1. NATURE OF OPERATIONS

Energas Resources Inc., was originally incorporated in 1989 in British Columbia,
Canada as a public company listed on the Canadian Venture Exchange. In 2001, the
Company registered as a Delaware corporation becoming a United States domestic
corporation. In 2002, its registration statement filed with the Securities and
Exchange Commission became effective and its stock is traded in the Over The
Counter (OTC) market.

The Company is primarily engaged in the operation, development, production,
exploration and acquisition of petroleum and natural gas properties in the
United States through its wholly-owned subsidiary, A.T. Gas Gathering Systems,
Inc., an Oklahoma corporation ("AT Gas"). AT Gas owns a natural gas gathering
system, located in Oklahoma, which serves the Company's wells for delivery to a
mainline transmission system. All of the Company's oil and gas property
interests are leased.

Although the Company has taken steps to verify title to resource properties in
which it has an interest, in accordance with industry standards for the current
stage of exploration of such properties, these procedures do not guarantee the
Company's title. Property title may be subject to unregistered prior agreements
and title may be affected by undetected defects.

The Company is in the process of acquiring and developing petroleum and natural
gas properties with adequate production and reserves to operate profitably. As
of January 31, 2003, it had a working capital deficiency of $1,457,865 and
incurred an operating loss of $(486,792) for the year then ended. The Company's
ability to continue as a going concern is dependent upon obtaining financing and
achieving profitable levels of operations. The Company is currently seeking
additional funds and additional resource property interests through private
placements of equity and debt instruments. There can be no assurance that its
efforts will be successful.

The consolidated financial statements do not give effect to any adjustments
which would be necessary should the Company be unable to continue as a going
concern and therefore be required to realize its assets and discharge its
liabilities in the normal course of business at amounts different from those
reflected in these consolidated financial statements.

2. SIGNIFICANT ACCOUNTING POLICIES

Basis of consolidation - The consolidated financial statements include the
accounts of the Company and its wholly-owned subsidiary, AT GAS. All significant
intercompany items have been eliminated in consolidation.

Use of estimates in the preparation of financial statements - The preparation of
financial statements in conformity with accounting principles generally accepted
in the United States of America requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

Revenue recognition - Oil and natural gas revenue is recognized at the time
title is transferred to the customer. Pipeline revenue is earned as a gathering
fee at the time the gas is delivered to the customer.

Petroleum and natural gas properties - The Company employs the full cost method
of accounting for petroleum and natural gas properties whereby all costs
relating to exploration and development of reserves are capitalized. Such costs
include land acquisition costs, geological and geophysical costs, costs of
drilling both productive and non-productive wells and related overhead.

<PAGE>



                             Energas Resources Inc.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002


2. SIGNIFICANT ACCOUNTING POLICIES (continued)

Petroleum and natural gas properties (cont.) - Capitalized costs, excluding
costs relating to unproven properties, are depleted using the unit-of-production
method based on estimated proven reserves, as prepared by an independent
engineer. For the purposes of the depletion calculation, proven reserves are
converted to a common unit of measure on the basis of their approximate relative
energy content. Investments in unproved properties are not amortized until the
proved reserves associated with the projects can be determined or until
impairment occurs. If an assessment of such properties indicates that properties
are impaired, the amount of impairment is added to the capitalized cost base to
be amortized.

In applying the full-cost method, the Company performs a ceiling test to ensure
that capitalized costs net of accumulated depletion do not exceed the estimated
future net revenues from production of proven reserves. The carrying value of
the properties is compared quarterly to estimated future net cash flows from
production or proven reserves. The present value of future net revenue from
proved reserves is estimated, using a 10% discount rate, based on current prices
less estimated future development and production costs. In addition, the cost of
properties not being amortized and the lower of cost or estimated fair value of
unproven properties included in the costs being amortized is added to the
present value of the future net revenues and this amount is adjusted for the
related tax effects for the purposes of computing the ceiling. During the years
ended January 31, 2003 and 2002, the Company recognized impairment of $-0- and
$6,665 to properly state its capitalized costs under the full cost method.

Proceeds on disposal of properties are normally applied as a reduction of the
capitalized costs without recognition of a gain or loss, unless such amounts
would significantly alter the relationship between capitalized costs and proved
reserves of oil and gas, in which case gain or loss would be recognized.
Abandonment of properties are accounted for as adjustments of capitalized costs
with no loss recognized, unless such adjustment would significantly alter the
relationship between capitalized costs and proved reserves of oil and gas
attributable to a cost center.

Long-lived assets - The Company reviews its long-lived assets for impairment
whenever changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. For purposes of evaluating the recoverability of
long-lived assets, the recoverability test is performed using estimated
undiscounted net cash flows to be generated by the asset.

Equipment - Office equipment, furniture and fixtures and software are recorded
at cost and depreciated using the declining balance method over useful lives of
3 to 5 years. Pipeline costs are depreciated using the straight-line method over
a period of 3 years.

Environmental liabilities - The Company expenses or capitalizes environmental
costs depending on their future economic benefit. Costs that relate to an
existing condition caused by past operations with no future economic benefit are
expensed. Liabilities for future expenditures of a non-capital nature are
recorded when future environmental expenditures and/or remediation is deemed
probable and the costs can be reasonably estimated. Costs of future expenditures
for environmental remediation obligations are not discounted to their present
value. During the years ended January 31, 2003 and 2002, the Company spent $-0-
and $1,304, respectively, on plugging and filling well holes, removing drilling
anchors, hauling and disposing of water and drilling mud, filling mud pits,
surface leveling and reseeding and general site clean up.

Financial instruments - The Company's financial instruments consist of cash,
accounts receivable, accounts payable, loans payable, and amounts due to
shareholder. It is management's opinion that the Company is not exposed to
significant interest, currency or credit risk arising from its financial
instruments and that their fair values approximate their carrying values, unless
otherwise noted.



<PAGE>


                             Energas Resources Inc.

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

Foreign currency translation - Foreign currency is translated in accordance with
Statement of Financial Accounting Standards No. 52, which provides the criteria
for determining the functional currency for entities operating in foreign
countries. The Company has determined its functional currency is the United
States (U.S.) dollar since substantially all of its operations are in U.S.
dollars. Financial statements of previous periods presented in Canadian dollars
have been translated to US dollars at rates prevailing during the year for
revenue and expense items and at year-end rates for assets and liabilities
except for fixed assets and prepaid expenses which are translated at the rate in
effect at the time of their acquisition. The net effects of currency
translations were not material in any period.

Earnings per share - The Company follows SFAS No. 128, Earnings per Share, for
computing and presenting earnings per share, which requires, among other things,
dual presentation of basic and diluted earnings per share on the face of the
statement of operations. Basic EPS is computed by dividing income available to
common shareholders by the weighted average number of common shares outstanding
for the period. Diluted EPS reflects the potential dilution that could occur if
securities, options or warrants were exercised or converted into common shares
or resulted in the issuance of common shares that then shared in the earnings of
the entity. For the years ended January 31, 2003 and 2002, no options or
warrants were considered common stock equivalents as their effect would be anti
dilutive.

Stock-based compensation - In October 1995, the FASB issued SFAS No. 123,
"Accounting for Stock-Based Compensation." SFAS No. 123 encourages, but does not
require, companies to record compensation expense for stock-based employee
compensation plans at fair value. The Company has elected to account for its
stock-based compensation plans using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" (APB No. 25). Under the provisions of APB No. 25, compensation cost
for stock options is measured as the excess, if any, of the quoted market price
of the Company's common stock at the date of grant over the amount an employee
must pay to acquire the stock.

Concentration - The Company sells all of its oil and gas production through a
related company operating its wells, Energas Pipeline Company. Energas Pipeline
Company currently sells the production to Conoco and Duke Energy. The Company
has determined that other customers for its production could replace its current
exclusive customers on a timely basis.

Cash and cash equivalents - For purposes of the statement of cash flows, the
company considers all highly liquid debt instruments purchased with a maturity
of three months or less to be cash equivalents.

Income taxes - Income taxes are accounted for under the asset and liability
method. Deferred tax assets and liabilities are recognized for future timing
differences between the financial statement carrying amounts and their
respective tax bases. Deferred tax assets and liabilities are measured using
enacted tax rates expected to apply to taxable income in the years in which
those temporary differences are expected to be recovered.

Recent pronouncements - In April 2002, the Financial Accounting Standards Board
("FASB") issued SFAS No. 145, "Rescission of FASB Statements No. 4, 44, and 64,
Amendment of FASB Statement No. 13, and Technical Corrections." Such standard
requires any gain or loss on extinguishments of debt to be presented as a
component of continuing operations (unless specific criteria are met) whereas
SFAS No. 4 required that such gains and losses be classified as an extraordinary
item in determining net income. The adoption of SFAS 145 did not have a material
effect on the Company's financial position or results of operations.



<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002

2. SIGNIFICANT ACCOUNTING POLICIES (continued)

Recent pronouncements (cont.) - In June 2002, the FASB issued SFAS No. 146,
"Accounting for Costs Associated with Exit or Disposal Activities." Such
standard requires costs associated with exit or disposal activities (including
restructurings) to be recognized when the costs are incurred, rather than at a
date of commitment to an exit or disposal plan. SFAS No. 146 nullifies EITF
Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)." Under SFAS No. 146, a liability related to an exit or disposal
activity is not recognized until such liability has actually been incurred
whereas under EITF Issue No. 94-3 a liability was recognized at the time of a
commitment to an exit or disposal plan. The provisions of this standard are
effective for exit or disposal activities initiated after December 31, 2002. The
adoption of SFAS 146 did not have a material effect on the Company's financial
position or results of operations.

On December 31, 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation--Transition and Disclosure." This standard amends SFAS No. 123,
"Accounting for Stock-Based Compensation," to provide alternative methods of
transition for a voluntary change to the fair value based method of accounting
for stock-based employee compensation. This standard also requires prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based employee compensation and the effect of the method
used on reported results. The adoption of SFAS 148 did not have a material
effect on the Company's financial position or results of operations.

3. PROPERTY AND EQUIPMENT
                                           Accumulated
                                           Depreciation/      Net Book Value
                                 Cost      Depletion        2003          2002
                              --------------------------------------------------
Unproved oil and gas
   properties                $   234,093     $      -    $ 234,093    $ 204,213
Proved oil and gas
   properties                    337,341       72,783      264,558      289,769
Office equipment                  18,913       11,969        6,944       11,276
Truck                             24,120       24,120            -            -
Pipeline                          24,750       24,750            -            -
Computer software                  2,400        2,400            -            -
                              --------------------------------------------------
                              $  641,617     $136,022    $ 505,595    $ 505,258
                              ==================================================

Oil and gas properties are accounted for using the full cost method as discussed
in Note 2. Depletion was $25,211 and $19,564 for the years ended January 31,
2003 and 2002, respectively.

4. NOTES PAYABLE
                                                     2003          2002
                                                  -----------    ---------
 Note payable to individual, bearing
   interest at 12%, payments of $5,000
   monthly, due March 6, 2003, secured
   by personal guarantee of Company's
   President and 200,000 shares of his
   stock in the Company                           $  34,542       $     -
 Note payable to individual, bearing
   interest at 25%, due December 2, 2000,
    refinanced by note described above                             50,000
                                                 -----------     ---------
                                                  $  34,542      $ 50,000
                                                ===========      =========


<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002

5. COMMON STOCK

The Company has authorized capital of 100,000,000 common shares with a $.001 par
value. The issued shares are as follows:

                                   2003                     2002
                                  Number      Amount       Number      Amount
                                ------------------------------------------------

Balance, beginning  of year     26,143,001  $7,647,920   22,459,153  $6,850,801
Shares issued for:
    Private placement, net of
        legal costs                     --          --    2,384,550     465,295
    Warrants exercised net of
        legal costs                     --          --      500,000     115,000
    Settlement of debt                  --          --      799,298     216,824
                                ------------------------------------------------
Balance, end of year            26,143,001  $7,647,920   26,143,001  $7,647,920
                                ================================================

In April 2001, the Company issued 384,550 shares of common stock and warrants to
purchase 384,550 shares of common stock at $.195 for $74,733 in a private
placement. Also, in July 2001, the Company had a private placement and issued
2,000,000 shares for $390,562.

In June 2001, the Company issued 400,070 shares of common stock for the relief
of debt of the Company's subsidiary due to a related party in the amount of
$138,800. Also, in September, 2001, the Company issued 399,228 shares of common
stock for the relief of $78,024 of debt.

In October 2001, a related party exercised warrants to purchase 500,000 shares
of common stock in relief of debt of the Company's subsidiary in the amount of
$115,000.

Options and warrants - The Company has issued stock options and stock warrants
as follows:

                     Outstanding  Granted    Exercised  Outstanding
           Exercise  January 31,    Or         or        January 31,  Expiration
            Price       2001     (Cancelled)  Expired       2002         date
           --------  ----------- ----------  ----------  ----------    --------
Options:    $ 0.17   1,835,000          -   (1,835,000)         -       8/24/01

Warrants:   $ 0.23     500,000          -     (500,000)         -      10/13/01
            $ 0.27      50,000          -      (50,000)         -      10/22/01
            $ 0.31      25,000          -      (25,000)         -       8/31/01
            $ 0.32     275,675          -            -    275,675      12/21/02
            $ 0.20           -    384,550            -    384,550       4/07/03



        Outstanding   Granted    Exercised   Outstanding
           Exercise  January 31,    Or           or      January 31,  Expiration
            Price       2002     (Cancelled)  Expired       2003         date
           --------  ----------- ----------  ----------  ----------   ---------
Warrants:   $ 0.32    275,675                (275,675)          -     12/21/02
            $ 0.20    384,550                             384,550      4/07/03*

* Expired unexercised

<PAGE>


                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002




6. RELATED PARTY TRANSACTIONS

The Company had oil and gas sales and pipeline revenue of $131,839 and $119,953
during the years ended January 31, 2003 and 2002 from Energas Pipeline Company
("EPC"), which is owned by the President of the Company. EPC purchases oil and
gas at the wellhead from the Company, generating oil and gas sales, and then
resells to Conoco and Duke Energy. EPC also pays a gathering fee to the Company
recorded as pipeline revenue.

The Company incurred oil and gas production and pipeline costs to Energas Corp.,
a company owned by the President of the Company, in the amounts of $47,337 and
$26,411 for the years ended January 31, 2003 and 2002.

In addition, the Company leases office space on a month-to-month basis from Shaw
Construction Company, owned by the President of the Company, and incurred rent
expense in the amount of $61,803 and $45,477 during the years ended January 31,
2003 and 2002.


7. DUE TO RELATED PARTIES AND NOTE PAYABLE TO SHAREHOLDER

                                                     2003          2002
                                                  -----------    ---------
 Open advances from related corporation
    owned by Company's  president,
    non-interest bearing                          $ 444,686      $349,860

 Note payable to shareholder, bearing
    interest at 12%, due April, 2002,
    unsecured                                       300,000            --

 Advance from shareholder, non-interest
    bearing                                         100,000            --

 Note payable to shareholder, non interest
    bearing, due May, 2002, unsecured                60,000

 Open advances from Company's president,
    non-interest bearing                             48,718            --

 Advance from shareholder, non-interest
    bearing                                          29,000            --

 Note payable to shareholder, bearing
    interest at 10%, due August, 2002, unsecured     25,000        25,000
                                                  -----------    ---------

                                                  $1,007,404     $374,860
                                                  ===========    =========


The Company entered into the loan agreement for $300,000 in April, 1999 to fund
a drilling program. The original loan was non-interest bearing and repayable on
the earlier of 3 years from the date the funds were advanced or 30 days after
the funds were utilized for pre-drilling costs on 10 separate oil and gas
prospects and initial test wells were commenced on each prospect. In addition,
the Company entered into the loan agreement for $60,000 with the same note
holder which was due in May, 2002. Interest expense was imputed for these notes
at a rate of 12% through their original due dates. Under the terms of the note
payable for $300,000, when it was not paid on its original due date, it became
interest bearing at the rate of 12%.



<PAGE>

                             Energas Resources Inc.

              NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (continued)

                      Years ended January 31, 2003 and 2002

8. INVESTOR ADVANCE PAYABLE

During the year ended January 31, 2003, the Company entered into an agreement
and received funds from an investor seeking to acquire an interest in its oil
and gas properties. The Company has not yet completed the transfer of any
interests in its oil and gas properties to the investor and, accordingly, the
funds received are recorded as a current liability in the accompanying
consolidated financial statements.

9.  INCOME TAXES

The Company has approximately $5,596,000 of net operating losses expiring
through 2023 that may be used to offset future taxable income but are subject to
various limitations imposed by rules and regulations of the Internal Revenue
Service. The net operating losses are limited each year to offset future taxable
income, if any, due to the change of ownership in the Company's outstanding
shares of common stock. In addition, at January 31, 2003, the Company had an
unused Canadian net operating loss carry-forward of approximately $395,000 USD,
expiring through 2008. These net operating loss carry-forwards may result in
future income tax benefits of approximately $2,294,000; however, because
realization is uncertain at this time, a valuation reserve in the same amount
has been established. Deferred income taxes reflect the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes.

Significant components of the Company's deferred tax liabilities and assets as
of January 31, 2003 and 2002 are as follows:

                                                2003          2002
         ------------------------------------------------------------
         Deferred tax liabilities          $       --    $        --
                                           ==========    ===========
          Deferred tax assets
              Net operating losses         $2,294,000    $ 2,167,697

              Valuation allowance for
                deferred tax assets        (2,294,000)    (2,167,697)
                                           ----------     ----------
                                           $       --    $        --
                                           ==========    ===========

The valuation allowance increased $126,303 and decreased $42,936 for the period
ending January 31, 2003 and 2002, respectively.

10. CONTINGENCIES

The Company is subject to federal, state and local laws and regulations
governing environmental quality and pollution control. During the years ended
January 31, 2003 and 2002, the Company spent $-0- and $1,304, respectively, on
plugging and filling well holes, removing drilling anchors, hauling and
disposing of water and drilling mud, filling mud pits, surface leveling and
reseeding and general site clean up. Although the Company believes that
compliance with environmental regulations will not have a material adverse
effect on its operations, risks of substantial costs and liabilities are
inherent in oil and gas production, and there can be no assurance that
significant costs and liabilities, including criminal penalties, will not be
incurred. Through the date of this report, the Company has no asserted or
unasserted environmental claims and no liability has been accrued in the
accompanying balance sheets.

The Company is in disagreement with a shareholder who advanced funds to both the
Company and an entity related to the Company as to the outstanding balances owed
to the shareholder. The shareholder is claiming additional amounts owed of
$300,000 to $400,000 related to this matter. The outcome of this matter cannot
presently be determined.

In addition, the Company has several past due notes payable (see Notes 4 and 7).
The Company has not been able to negotiate new terms with the lenders. The
outcome of these matters cannot presently be determined.

<PAGE>




                             Energas Resources, Inc.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)

                      Years ended January 31, 2003 and 2002


                                                  2003       2002
                                                ---------  ----------
Capitalized Costs Relating to Oil and
Gas Producing Activities at January 31,

Unproved oil and gas properties                $ 234,093    $204,213

Proved oil and gas properties                    337,341     337,341
                                                ---------  ---------
                                                 571,434     541,554

Less accumulated depreciation, depletion,
amortization, and impairment                     (72,783)    (47,572)
                                                ---------  ----------

      Net capitalized costs                     $ 498,651   $ 493,982
                                                =========  ==========

Costs Incurred in Oil and Gas
Producing Activities For the Year Ended
Janaury 31,

Property acquisition costs
    Proved                                             --           --
    Unproved                                     $ 29,880           --

Exploration costs                                       --          --
Development costs                                       --          --
Amortization rate per equivalent
   barrel of production                          $    4.57    $   5.32

Results of Operations for Oil and Gas
  Producing Activities For the Year Ended
   January 31,

Oil and gas sales                                $ 116,031    $ 104,411
Gain on sale of oil and gas properties                  --           --
Gain on sale of oil and gas leases                      --           --
Production costs                                   (26,544)    (23,119)
Exploration expenses                                    --          --
Depreciation, depletion, and amortization          (25,211)    (26,229)
                                                  ---------   ----------
                                                    64,276      55,063
Income tax expense                                      --          --
                                                 ---------    ----------

Results of operations for oil and gas
  producing activities (excluding
  corporate overhead and financing costs)        $  64,276   $  55,063
                                                 =========   ==========




<PAGE>





                             Energas Resources, Inc.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)

                      Years ended January 31, 2003 and 2002


The following estimates of proved and proved developed reserve quantities and
related standardized measure of discounted net cash flow are estimates only, and
do not purport to reflect realizable values or fair market values of the
Company's reserves. The Company emphasizes that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available. All of the Company's reserves
are located in the United States.

Proved reserves are estimated reserves of crude oil (including condensate and
natural gas liquids) and natural gas that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs under existing economic and operating conditions. Proved
developed reserves are those expected to be recovered through existing wells,
equipment, and operating methods.

The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves, less estimated future income tax expenses (based on year end statutory
tax rates, with consideration of future tax rates already legislated) to be
incurred on continuation of existing economic conditions. The estimated future
net cash flows are then discounted using a rate of 10 percent a year to reflect
the estimated timing of the future cash flows.




<PAGE>


                             Energas Resources, Inc.

                      SUPPLEMENTAL INFORMATION (UNAUDITED)

                      Years ended January 31, 2003 and 2002

                                       2003                   2002
                                -------------------   -------------------
                                  Oil       Gas         Oil       Gas
                                 (Bbls)    (Mcf)       (Bbls)    (Mcf)
                                --------- ---------   --------- ---------
 Proved developed and
   undeveloped reserves
     Beginning of year            6,842    713,262       8,909   730,441
     Revisions of previouS
        estimates                (2,678)  (84,806)           -         -
     Improved recovery                -         -            -         -
     Purchases of minerals
       in place                       -         -            -         -
     Extensions and discoveries       -         -            -         -
     Production                    (403)  (30,683)      (2,067)  (17,179)
     Sales of minerals in place       -         -            -         -
                                --------   -------     -------   --------
End of year                       3,761   597,773        6,842   713,262
                               =========  ========     =======   ========

Proved developed reserves
    Beginning of year             6,842   713,262        8,909   730,441
    End of year                   3,761   597,773        6,842   713,262


                                                2003              2002
                                             -----------      -----------
Standardized Measure of Discounted Future
Net Cash Flows -
    Future cash inflows                     $  2,976,046      $ 1,763,748
    Future production  costs                    (828,826)        (425,642)
    Future  development costs                         --               --
    Future income tax  expenses                       --               --
                                            ------------      -----------
    Future net cash flows                      2,147,220        1,338,106

   10% annual discount for estimated
      timing of cash  flows                   (1,255,810)        (844,124)
                                              -----------      -----------
    Standardized measures of discounted
       future net cash flows relating
       to proved oil and gas reserves         $  891,410       $  493,982
                                              ==========        ==========

The following reconciles the change in the
standardized measure
     of discounted future net cash
    flow during 2003

Beginning of year                            $   493,982       $  525,211
Sales of oil and gas produced, net of
    production costs                             (62,617)        (100,016)
Net changes in prices and production costs       522,423          (56,652)
Extensions, discoveries, and improved recovery,
    less related costs                                 -                -
Development costs incurred during the year
   which were previously estimated                     -                -
Net change in estimated future development
   costs                                               -                -
Revisions of previous quantity estimates        (136,799)         (91,875)
Net change from purchases and sales of
    minerals in place                                                   -
Accretion of discount                             49,398           52,744
Net change in income taxes                                              -
Other                                             25,023          164,570
                                             -----------       -----------
End of year                                   $  891,410       $  493,982
                                             ===========       ===========




<PAGE>
                                         SIGNATURES

     In accordance  with Section 13 or 15(a) of the Exchange Act, the Registrant
has caused this Report to be signed on its behalf by the undersigned,  thereunto
duly authorized on the 15th day of May 2003.

                                  ENERGAS RESOURCES, INC.

                                  By  /s/ George G. Shaw
                                      George G. Shaw, President and Chief
                                      Executive Officer

                                  By /s/ David W. Young
                                     David W. Young, Chief Financial Officer

     Pursuant to the requirements of the Securities Act of l934, this Report has
been signed below by the following  persons on behalf of the  Registrant  and in
the capacities and on the dates indicated.

                                     Title                    Date

/s/ George G. Shaw
George G. Shaw                      Director             May 15, 2003

/s/ G. Scott Shaw
G. Scott Shaw                       Director             May 15, 2003

/s/ David W. Young
David W. Young                      Director             May 15, 2003


James H. Attarian                   Director

                                       CERTIFICATION

     In  connection  with the Annual  Report of  Energas  Resources,  Inc.  (the
"Company")  on Form 10-KSB for the year ended January 31, 2003 as filed with the
Securities and Exchange Commission on the date hereof (the "Report"), we, George
G. Shaw, the President and Chief Executive Officer and David W. Young, the Chief
Financial Officer of the Company,  certify,  pursuant to 18 U.S.C. Section 1350,
as adopted  pursuant to Section 906 of the  Sarbanes-Oxley  Act of 2002, that to
the best of our knowledge:

(1)  The Report fully complies with the  requirements  of Section 13(a) or 15(d)
     of the Securities Exchange Act of 1934; and

(2)  The information  contained in the Report fairly  presents,  in all material
     respects the financial condition and results of the Company.

Date:  May 15, 2003
                                 By: /s/ George G. Shaw
                                         George G. Shaw, President and Chief
                                         Executive Officer

                                   /s/ David W. Young
                                   David W. Young, Chief Financial Officer
<PAGE>


                               CERTIFICATION PURSUANT TO THE
                                     SARBANES-OXLEY ACT

I, George Shaw, the Chief Executive Officer of Energas Resources,  Inc., certify
that:

1. I have reviewed this annual report on Form 10-KSB of Energas Resources, Inc.;

2.  Based on my  knowledge,  this  annual  report  does not  contain  any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. I am responsible for  establishing  and maintaining  disclosure  controls and
procedures  (as  defined  in  Exchange  Act Rules  13a-14  and  15d-14)  for the
registrant and have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to me by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;

     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented in this annual report my conclusions about the effectiveness
          of the disclosure controls and procedures based on my evaluation as of
          the Evaluation Date;

5. I have disclosed,  based on my most recent  evaluation,  to the  registrant's
auditors and the audit committee of registrant's  board of directors (or persons
performing the equivalent functions):

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6. I have indicated in this annual report whether there were significant changes
in  internal  controls  or in other  factors  that  could  significantly  affect
internal controls subsequent to the date of my most recent evaluation, including
any  corrective  actions with regard to  significant  deficiencies  and material
weaknesses.



Date: May 15, 2003                   /s/ George Shaw
                                     George Shaw, Chief Executive Officer

<PAGE>


                               CERTIFICATION PURSUANT TO THE
                                     SARBANES-OXLEY ACT

I, David W.  Young,  the Chief  Financial  Officer of Energas  Resources,  Inc.,
certify that:

1. I have reviewed this annual report on Form 10-KSB of Energas Resources, Inc.;

2.  Based on my  knowledge,  this  annual  report  does not  contain  any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

3.  Based  on my  knowledge,  the  financial  statements,  and  other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. I am responsible for  establishing  and maintaining  disclosure  controls and
procedures  (as  defined  in  Exchange  Act Rules  13a-14  and  15d-14)  for the
registrant and have:

     a)   designed  such  disclosure  controls  and  procedures  to ensure  that
          material  information  relating  to  the  registrant,   including  its
          consolidated subsidiaries,  is made known to me by others within those
          entities,  particularly  during the period in which this annual report
          is being prepared;

     b)   evaluated the  effectiveness of the registrant's  disclosure  controls
          and procedures as of a date within 90 days prior to the filing date of
          this annual report (the "Evaluation Date"); and

     c)   presented in this annual report my conclusions about the effectiveness
          of the disclosure controls and procedures based on my evaluation as of
          the Evaluation Date;

5. I have disclosed,  based on my most recent  evaluation,  to the  registrant's
auditors and the audit committee of registrant's  board of directors (or persons
performing the equivalent functions):

     a)   all  significant  deficiencies  in the design or operation of internal
          controls  which could  adversely  affect the  registrant's  ability to
          record,  process,   summarize  and  report  financial  data  and  have
          identified for the  registrant's  auditors any material  weaknesses in
          internal controls; and

     b)   any fraud, whether or not material,  that involves management or other
          employees who have a  significant  role in the  registrant's  internal
          controls; and

6. I have indicated in this annual report whether there were significant changes
in  internal  controls  or in other  factors  that  could  significantly  affect
internal controls subsequent to the date of my most recent evaluation, including
any  corrective  actions with regard to  significant  deficiencies  and material
weaknesses.



Date: May 15, 2003                   /s/ David W. Young
                                     David W. Young, Chief Financial Officer